Steam cycle options for the retrofit of coal and gas power plants with postcombustion capture Academic research paper on "Chemical engineering"

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Energy Procedia 4 (2011) 1812-1819 ;

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GHGT-10

Steam cycle options for the retrofit of coal and gas power plants with postcombustion capture

Mathieu Lucquiauda*, Jon Gibbinsa

aThe University of Edinburgh, The King's Buildings,MayfieldRoad, Edinburgh, EH1 2DP, UK

Abstract

In a period where fast learning-curves for capture technologies can be expected it is important that plants built as carbon capture-ready avoid becoming potential stranded assets during the period of time when the plant operates without capture. At the same time recent evidence shows that decarbonisation of electricity generation cannot be achieved without a CCS option for gas plants. This article first proposes steam turbine design options to build combined cycle gas turbine plants as carbon capture-ready. Then steam cycle options for the existing fleet of coal-fired units are then presented. Although these plants have not been initially designed to operate with CCS it is possible to achieve effective thermodynamic integration - and an overall electricity output penalty in kWh per tonne of CO2 close to a plant built with capture from the outset - with appropriate steam turbine retrofits.

Finally, novel insights into the design of capture-ready steam cycles are discussed for future-proofing pulverised coal plants that may have capture fitted after the first learning cycles of postcombustion capture technologies occur or that may be upgraded over their lifetimes.

(©5 2011 Published by El sevier Ltd.

Steam cycle, capture-ready, retrofit, post-combustion capture, coal, gas

1. Introduction

Although power generation from coal has received more attention so far, deep decarbonisation of electricity production may not be feasible in many countries without deployment of CCS on natural gas combined cycle gas turbine (CCGT) plants too. The UK Committee on Climate Change [1] suggests that the level of average specific emissions from electricity generation must fall rapidly to below 100g CO2 per kWh by 2030, and further down to 50 g CO2 per kWh by 2050. For comparison, the current system average level is around 500 gCO2 per kWh in the UK while unabated emissions for gas plants are around 350-500 g CO2 per kWh at full load and 750-1000 gCO2 per kWh for coal plants. Recent EU directives for making power plants CO2 capture ready (CCR) already apply to all CO2-emitting power plants at or above 300MW output [2], and these are likely to see counterparts in other economies if the expected probability of future CCS grows. Globally, growing numbers of new CCGT can therefore be expected to be built CCR, at first, and then possibly be retrofitted with CCS over their operating lifetime.

New-build coal units built in the UK are now required to be fitted with at least a part of their carbon emissions

* Corresponding author. Tel.: +44-131-650-4867; E-mail address: m.lucquiaud@ed.ac.uk

ELSEVIER

doi:10.1016/j.egypro.2011.02.058

abated with CCS, a trend that appears to be growing in developed countries. In the UK this initial step is likely to be subsequently followed by a "CCS-upgrade" in the 2020's to a higher level of capture to reduce specific emissions further down to the required rate of decarbonisation by 2030. The existing coal fleet can possibly also expect to undertake a staged introduction of CCS. Efforts for aggressive deployment of CCS in developed countries will however be undermined if coal plants built in developing countries are not made CCR, so that it is clear that their carbon emissions over the next decades can also be abated.

This article presents steam cycle options for retrofitting CCGT plants. Since the economics of retrofit depend critically on unknown parameters such as the timing for fitting capture and other regulatory developments and future fuel and CO2 prices, the approach suggested here is to implement CCR plants with options incurring only minimal upfront capital costs and with little or no effect on plant performance prior to retrofit. Utilities therefore face no need to resolve the uncertainty surrounding the timescale for a retrofit in order to justify any initial capital investments or generation revenue losses. Attention is then given to the existing fleet of coal-fired units. Existing steam cycles have not been designed for a retrofit with CCS and therefore do not necessarily have the optimal steam conditions for steam extraction for solvent regeneration. The extent to which the non-site-specific base power plant efficiency, and in particular the peak steam temperature and pressure used in the plant (rather than other site specific factors such as ambient temperature, cooling method, coal properties, duty cycle) affect plant efficiency and hence retrofit economics is a topic of concern. Steam turbine retrofit options are proposed that can give effective thermodynamic integration of the capture system with the power cycle, resulting in an energy output penalty, in kWh per tonne of CO2 captured close to new-build units and independent of the initial steam conditions and steam turbine design. Finally, new-build coal plants in developing countries with a fast build rate of power stations are considered. It is unlikely that these plants will be retrofitted until capture technologies have reached a certain level of maturity, most likely after the first learning cycle(s) are completed on demonstration plants in developed countries. Previous work by the authors on steam turbine options for CCR coal plants is extended by novel insights into additional design options to permit the use of radically different solvents without committing the plant to a specific technology.

2. General principles for the design of capture-ready steam turbines

It is generally accepted that the energy penalty for post-combustion carbon dioxide capture from fossil-fired power plants can be significantly reduced - independently of the intrinsic energy of regeneration of the solvent used - by effective thermodynamic integration with the power cycle. Yet expected changes in electricity generation mix, and the current immaturity of post-combustion capture technology make effective thermodynamic integration throughout the operating life of a power plant a challenging objective to achieve. This problem has not been addressed by most studies in this area, which so far have assumed base-load operation of the power cycle and the carbon dioxide capture plant and also that the capture technology is fixed throughout the life of the plant.

In practice, although developers of capture ready plants must show regulators that all barriers for a retrofit using current technology at the time of permitting have been removed, the characteristics of capture systems when the plant is retrofitted are not known, or at least uncertain. Capture-ready plants thus need to be able to be retrofitted with unknown improved solvents and to be capable of integration with a range of future solvents. To achieve effective integration the turbines will need to be able to provide a specific amount of steam at a specific temperature for the regeneration of the solvent, but neither of these requirements will be known in advance. Solvent thermal stability will generally be the main factor determining the pressure of the steam leaving the boundaries of the turbine island, and the energy of regeneration will determine the amount of steam required for releasing the CO2 from the solvent. It is thus important that capture-ready steam turbines are designed to provide a range of regeneration temperatures and steam extraction rates. Capture-readiness also needs to be achieved at minimal cost. Several studies [3, 4] have highlighted the absence of economic drivers to make large pre-investment for capture-ready designs worthwhile and pointed out that, beyond space and access, significant capital pre-investments do not appear to be justified by the cost reductions that can be achieved when capture is added.

For the same reason, capture-ready plants must operate before capture without being at a competitive disadvantage with 'standard' units, with their turbine heat rate matching the heat rate of similar units with the same steam conditions. Performance when capture is added obviously matters, although the time value of money makes performance in the later years of the plant operating life less critical than during its first years of operation.

Finally, the reliability of the power generation asset, i.e. the ability to export power during outages of the capture island, obviously matters to 'keep the light on'. Retrofitted steam turbines should be capable of returning to their nominal power output at times when steam extraction is no longer used.

3. Steam cycle options for retrofitting combined cycle gas turbine plants

In some CCGT steam turbine configurations the IP and LP turbines are in separate cylinders with crossover pipes between them. A stand alone HP turbine with a combined IP/LP cylinder is another common design option, with different implications for future retrofits with post-combustion capture. In the first configuration condensing steam for

solvent regeneration can be extracted from the IP/LP crossover and then desuperheated using a spray with condensate from the solvent reboiler, provided that that IP/LP crossover pressure is above the steam pressure required by the solvent. In the second configuration access for extraction of large amount of steam from the IP/LP crossover is virtually impossible and alternative retrofit and capture-ready design approach for this specific case need to be considered.

Several steam cycle configurations are proposed and shown schematically in Figure 1. Capture-ready considerations are discussed where appropriate. Alternative capture-ready configurations are also included, for when the IP/LP crossover pressure is higher than the minimum necessary for solvent regeneration, either because of a desire to use an existing turbine design, or to give a margin in purposely-designed plants to accommodate new solvents. Additional measures are also discussed which can be taken at the time of retrofit to guarantee effective thermodynamic integration with capture. To avoid future confusion it should be noted that, amongst the retrofit options proposed in Figure 1, some of these retrofit options are worth pursuing for capture-ready design - option b) and c) - while others are proposed for illustrative purposes in order to highlight the consequences of poor thermodynamic integration with capture - option d), e) - or technology lock-in - option a).

3.1 Replacement of the LP turbine cylinder

The existing LP steam turbine is replaced by a new LP turbine cylinder when capture is retrofitted. If economically justified, the extracted steam can be expanded through an additional back-pressure turbine added at the time of retrofit (rather than a throttling valve) if the IP/LP crossover pressure is above the required pressure for solvent regeneration. The design steam flow for the new LP turbine exactly matches the flow available once steam has been extracted for the CO2 capture system. This option involves additional capital costs compared to a standard retrofit, but gives the option to achieve a system that is similar in performance to a new-build NGCC power plant with post-combustion capture. It can be seen as the reference case for other capture-ready design and retrofit options in terms of performance with capture -and conversely also a worst case scenario for future-proofing flexibility. Since the LP turbine is sized for capture operation only and the extraction pressure set at the crossover pressure the plant owner is locked into retrofitting possible solvents with a regeneration temperature identical to or lower than that required for the initial solvent and with an identical or higher energy of regeneration.

3.2 Pass-out back-pressure turbine from reheater outlet

Access for steam extraction at the LP inlet may prove to be difficult for configurations with a combined IP/LP cylinder and hence no IP/LP crossover. Large amounts of steam can instead be extracted at the reheater outlet and again space needs to be provided to do this, with a spool piece at the front of the IP turbine (Space for steam extraction is also available at the reheater inlet, but this would affect heat transfer downstream in the flue gas path and so would necessitate modifications to the HRSG as well). The pressure and temperature conditions are obviously unsuitable for use directly for solvent regeneration, while both the IP and LP turbine now operate at reduced flow, which modifies the pressure ratio across the IP and LP turbine and decreases the absolute steam pressures.

This modifies the blade velocity triangles and slightly reduces the overall turbine efficiency (See [5] for further details). To match steam conditions to the IP/LP cylinder and the capture plant a tailored design pass-out back pressure turbine comprising three distinct groups of blades is fitted, as shown in Figure 1 option b). The steam leaving the reheater is expanded down to the new IP turbine inlet pressure. Steam required for capture is then expanded in the second group of blades of the additional turbine, whilst the remaining flow is returned to the IP turbine. The third group of blades keeps the LP superheater in operation when capture is fitted. Unlike the previous option a wide range of possible solvents can be accommodated when the plant is retrofitted since steam is available at up to the reheater outlet pressure - 27 bar in this example -, and since the pass-out turbine is only sized at the time of retrofit.

3.3 Retrofit with two back-pressure turbines

The IP/LP crossover pressure does not limit solvent selection provided that the pressure is set above future expected requirements for solvent regeneration. A back-pressure turbine can be fitted in the steam extraction line to generate power while reducing the steam pressure to the desired value in the reboiler, while a second back-pressure turbine is fitted before the steam enters the LP turbine, which would otherwise have to be throttled. Both turbines are sized at the time of retrofit and their designs can be tailored to the solvent selected. The principal additional items for retrofit or CCR consideration include space and foundations in the turbine hall for the back-pressure turbines (and their dedicated generator if required, or provision for connection via a clutch) and a spool piece in the IP/LP crossover for a tee to facilitate steam extraction.

b) RETROFIT WITH A PASS-OUT BACK-PRESSURE TURBINE

c) RETROFIT WITH TWO BACK-PRESSURE TURBINES

(from hot RH or IP exit, depending on access and pressures available and required

reboiler

d) LOW_EFFICENCY RETROFIT WITH TWO THROTTLE VALVES

reboiler

e) - f) LOW EFFICIENCY RETROFIT WITH ANCILLARY BOILER AND OPTIONAL BACK-PRESSURE TURBINE

reboiler

Figure 1: Steam cycle retrofit options for natural gas combined cycle plants 4. Retrofit with a separate ancillary boiler and an optional back-pressure turbine

Inadequate retrofit options can possibly affect the viability of power plant projects with CCS. The addition of a separate ancillary natural gas boiler providing steam for solvent regeneration was initially proposed for coal plants, and has since been mostly disregarded in favour of steam extraction. It has recently been proposed in feasibility studies by applicants seeking planning consent of CCGT projects in the UK (See for example [6]). This option follows some of the general principles discussed previously. The drawback is low efficiency. Great efforts have been deployed to improve the efficiency of NGCC plants up to 55-60% LHV level because it makes economic sense to do so. The calorific value of natural gas is used at very high temperatures in the gas turbine, then high pressure, high temperature steam is raised from the gas turbine exhaust. Most of the energy coming from the fuel is used and low grade heat is rejected in the gas turbine exhaust at around 80-100°C and in the steam cycle condenser at around 30°C. Providing energy for solvent regeneration by extracting low pressure steam from the turbines repeats the above, only differing in the temperature of condensation. The steam required for capture is condensed in the solvent reboiler at temperatures from 100°C to perhaps 150°C, depending on the solvent used. In contrast, separate ancillary boilers do not make use of the full potential of the

fuel calorific value. They turn the energy in the gas to heat at this same low reboiler temperature, missing out all the opportunity to extract higher-grade electrical energy.

Adding a separate boiler does not, however, require any modifications to the steam turbines, and by extension avoid locking-in the plant to a specific solvent while most of the electrical output from the plant can be retained. If the boiler is used to generate superheated steam at a higher pressure, which is then expanded through a back-pressure turbine upstream of the reboiler, additional power is available for ancillary consumption of the amine plant and the compression train. The plant can then operate with the same net output to the grid before and after capture is fitted.

The boiler and turbine still does not, however, use fuel with the same thermodynamic efficiency as a combined cycle system and an option that gives better efficiency (although not discussed in detail here) may be to use either a smaller additional GTCC unit (also with capture) to meet the power 'loss' and some of the heat requirement (as necessary) or a larger GTCC unit to supply all of the heat required for capture units and additional power.

5. Base-load performance of combine cycle gas turbine retrofits

This analysis is based on the gas plant cases of a comprehensive study commissioned for the IEAGHG [7] with the ancillary power for CO2 capture and compression taken from the Fluor Econoamine FG Plus case. This is expected to be a 'worst case' compared to best available technology in 2010 and beyond, and so there is an expectation that this gives a maximum value for the range of possible future steam extraction rates. Advanced steam turbine cycle models have been developed in the equation-based software gPROMs (www.psenterprise.com/gproms) to evaluate the base-load performance of each configuration.

For additional details on modelling the reader is referred to [5]. It is worth noting that, for consistency between cases, the availability of cooling water is identical for the requirements of capture and compression so the condenser pressure falls when the mass flow of steam is reduced. Equally, the same CO2 removal rate is used between cases, i.e. emissions arising from additional fuel burnt when an ancillary boiler is used are included.

For the purpose of comparison of ancillary boiler options two performance metrics need to be introduced. First, the gas usage per tonne of CO2 abated is a useful metric to quantify the principal operating cost, the fuel, for the different capture options:

(MWth/MWe w CCS - MWth/MWe w/o CCS) / (kg CO2/MWhe w/o CCS - kg CO2/MWhe w CCS)

A second useful performance metric is the equivalent electricity output penalty per tonne of CO2 captured, defined as the difference in power output between the capture plant and an unabated reference GTCC plant burning the same amount of gas, divided by the difference in the mass of CO2 emitted to atmosphere, as below.

EOPeq = (Qbr * n - W) / (E - Er)

kWh/tCO2 Equivalent electricity output penalty of capture and compression

MWth Gas input with capture

LHV efficiency of NGCC plant without capture MWe Net power output of NGCC plant without capture

kg/s CO2 emissions without capture for the reference GTCC plant

kg/s CO2 emissions with capture

A comparison of the steam cycle options is presented in Table 1 overleaf. It is worth noting that the performance of the LP replacement retrofit option is slightly improved compared to a new-build plant with capture with same steam conditions due to the assumptions which lead to a lower condenser pressure when LP steam flows are reduced.

Table 1: Comparison of capture-ready steam cycle options for combined cycle gas turbine plants

LP turbine replacement Two back-pressure Turbines Pass-out back-pressure turbine Ancillary boiler (with optional backpressure turbine)

Provision for cylinder

Main specific capture-ready design actions replacement IP/LP crossover pressure set for predicted reboiler temperature Space and foundations reinforcement for turbines Space and foundations reinforcement for turbines Space for boiler (space for back pressure turbine)

Efficiency before capture (% point LHV) 55.4 55.4 55.4 55.4

Penalty before capture None None None None

Capture rate (%) 85 85 85 85

Efficiency with capture (% point LHV) 48.2 48.2 48.1 42.5 (44.2)

Performance with capture Reference + 1.9 kWh/tCO2 + 3.3 kWh/tCO2 + 487.6 kWh/tCO2 (+ 418.9 kWh/tCO2)

Gas usage per tonne abated (MWhth/tCO2) 0.87 0.88 0.88 1.82 (1.50)

CO2 emissions (g/kWh) 58.8 58.8 58.8 65.8 (63.5)

extra CAPEX before retrofit Likely to be < 1% Likely to be < 1% Likely to be < 1% Likely to be < 1%

extra CAPEX compared to new-build CCS unit New LP turbine cylinder Cost of back-pressure turbines Cost of pass-out backpressure turbine Ancillary boiler (optional back-pressure turbine)

Retrofit with higher/lower temperature solvents Capacity to export additional power with improved solvents NO/YES NO YES/YES YES YES/YES YES YES/YES YES (NO)

6. Retrofit options for existing pulverized coal plants

Low plant efficiency and poor performance with capture compared to new-build projects are often cited as critical barriers to the retrofit of existing units. It is true that the steam turbines of existing coal-fired power plants were not designed for the extraction of large amount of steam for solvent regeneration. The loss of power per unit tonne of CO2 captured is, however, the same irrespectively of the boiler steam conditions between two plants with different steam conditions and hence base plant efficiency, provided that the turbine retrofit can achieve effective thermodynamic integration with the CO2 capture plant and associated CO2 compressors.

By extension this also implies that the abatement costs (or cost per tonne of CO2 emissions avoided) for retrofitting existing units is independent of the initial plant efficiency [8]. There are several options available to power plant developers for effective steam turbine retrofit with post-combustion capture. They are discussed in details in [8], and the main results are highlighted here. First, it should be noted that site-specific circumstances are likely to drive the technical aspects of steam turbine retrofits. Avoiding thermodynamic inefficiencies through valve losses is the main driver. This can be done with non-controlled steam extraction. This, however, results in a pressure drop, an increase in steam specific volume, stage pressure ratio and stage enthalpy drops in the stages upstream of the extraction point. These variations mainly affect the stage located just before the extraction point, and are greatly attenuated on all the other stages further upstream. The increased stage pressure drop is of particular concern because of greater forces on the sides of the turbine stator. Likewise, an increase in the enthalpy drop results in a higher stage output, and hence higher flexural stresses in the rotating blades. Given the large amount of extraction required for post-combustion capture a much wider blade profile is needed to withstand the forces for a non-controlled extraction option to become available. Reblading the last stages of the IP turbine with a wider blade profile (or possibly alternative blade materials) has to be done within the constraints of the existing turbine casing, but could be an attractive retrofit option. A dedicated back-

pressure turbine can be fitted in the steam extraction line if the IP/LP crossover pressure does not drop to exactly the pressure required for the amine plant.

If the last stages of the IP turbine cannot be rebladed, a tailored design pass-out back-pressure turbine or two dedicated back-pressure turbines - similar to the options proposed for CCGT in this paper - can achieve good performance irrespectively of the initial IP/LP crossover pressure of the plant.

Figure 2 provides an overview of the performance of the two back-pressure turbine option and the IP reblading option with a floating crossover pressure and a back-pressure turbine in the extraction line for a range of initial IP/LP crossover pressure, and compares performance with a straightforward retrofit with a controlled extraction and a backpressure turbine in the extraction line.

-floating IP/LP crossover pressure, heat integration and back pressure turbine

^^ valve at LP turbine inlet, heat integration and back pressure turbine

□ pass-outback pressure turbine

IP/LP crossover pressure (bara)

Figure 2: Comparison of the electricity output penalty of steam turbine retrofit options for a range of initial IP/LP crossover pressure. 90% capture rate - 125 kWh/tCO2 electricity output penalty for ancillary and compression power - solvent heat of regeneration of 3.2 GJ/tCO2 - 94% boiler thermal efficiency

7. Future-proofing turbines against potential changes of solvent

Selecting capture-ready options for steam turbine design in an era of rapid development of CCS and likely technology change before capture retrofit is a challenging task. The main risk facing power plant developers is that the CCR plant will be locked in to an unnecessarily low level of performance with capture after improved solvents become available. Initial work by the authors in [9] presented options for capture-ready steam turbines for pulverized coal plants capable of being retrofitted with capture using what were then considered to be state-of-the-art solvents. Future solvents may include those with higher enthalpy of absorption or higher temperature of regeneration [10], to maximize the benefits of thermal compression during the thermal swing between the absorber and the stripper of the amine plant. Favourable trade-offs between the higher quality of the steam extracted from the power cycle and lower compression power may be able to reduce the overall electricity output penalty of CCS [11].

A large fraction of the global coal fleet, which will be built in the next decade, will not be expected to fit capture before a general CCS roll-out, and some of these plants may be retrofitted with radically different solvents from those available at the time they were designed. In this case, technology lock-in can be avoided by opting either for retrofit with an external heat source, or by avoiding a technology-driven commitment to a steam extraction pressure and flow rate. In the former case, a separate CHP coal plant can be used to generate heat for solvent regeneration and the ancillary power for the amine plant, the compression train and possibly the main power plant. This could also be achieved with a separate gas turbine attached to a combined cycle. In the latter case, the IP/LP crossover pressure can be set to a relatively high value to be able to cover for a wide range of solvent regeneration temperatures, and/or arrangements for future steam extraction from the reheater outlet can also be made (space, access, foundations reinforcements, etc).

The implications of upgrading the solvent used for capture within the constraints of an existing power generation asset attached to a dedicated capture and compression plant are complex. Power generation assets can be future-proofed in this respect if it was designed with the capability of operating without capture - and by extension at reduced steam extraction level; this might anyway occur if post-combustion capture was being developed through staged addition of capture modules to new-build units. These issues are addressed further in [12] and in a forthcoming report by the IEAGHG R&D Programme.

8. Conclusions

New coal and new gas plants built as capture-ready may want to keep their retrofit options open by building plants capable of fitting radically different solvents from current state-of-the-art amines, particularly in countries not yet committed to CCS. The capture-ready turbines options proposed in this paper avoid locking-in power plant developers to a specific solvent technology whilst following the general principles of capture-ready design of low additional capital cost, no upfront performance penalty, good performance with capture and the ability to operate with the capture unit bypassed.

Steam cycle options to retrofit the existing fleet of coal-fired units are also examined. Although these plants have not been initially designed to operate with CCS they can achieve performance with capture close to a plant built with capture from the outset independently of the initial plant steam conditions and efficiency with appropriate steam turbine retrofits. This increases the number of opportunities for potential retrofits of post-combustion capture by adding sites that may previously have failed to be considered on the grounds of a low base plant thermal efficiency.

Acknowledgments

The authors are grateful for funding from the UKCCSC through the TSEC project, the UK Department of Energy and Climate Change, the International Energy Agency Greenhouse Gas R&D Programme and the UK Technology Strategy Board through the CASS-CAP project. In-kind contribution as free gPROMS licenses from Process System Enterprise is also gratefully acknowledged.

References

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